This is what the North’s first frack job looked like

For such an historic event, the whole thing is profoundly anticlimactic. As the first horizontal fracking operation in NWT history gets underway, I am inside an ATCO trailer at the site of well P20, at ConocoPhillips’s Canol shale operation, attempting to shoehorn myself out of a set of mandatory fire-retardant coveralls that do not flatter my figure.

I am okay with this, because I have already been told precisely how unexciting a fracking operation is to watch in person. 

I suppose I expected a series of loud cracks or ungodly subterranean groans as the pressurized mixture of water, sand and lubricating chemicals is shot 2,000 metres into the earth, shattering open the shale below and—ConocoPhillips hopes—releasing enough oil to prove their parcel on the west bank of the Mackenzie River is economically viable.

Earlier, I am outside regarding the assembly of trucks, klieg lights, pipes, hoses and machinery that surrounds the wellhead as though it were some kind of shrine. Which, in a sense, it is. Jim Rau, the man in charge of the actual fracking at this well, chuckles when I tell him what I’m hoping for. “You know what’s gonna happen?” he asks over the din of dozens of idling diesel engines. “The trucks are going to rev a little bit louder.” He is a portly, affable oilpatch veteran, profoundly uncomfortable when asked to give a formal presentation for the assembled media (that is, me and one CBC reporter), and supremely at ease casually explaining his job. He is an oil guy, not a media guy, but he can see that my idea of a spectacular lead has evaporated. “Sorry to disappoint,” he says, and he means it.

Maybe I am not the only one to walk away from P20 underwhelmed. Two months after fracking the well, ConocoPhillips announced it is suspending plans to frack two more wells at exploration license 470 in 2015. Spokeswoman Lauren Stewart tells me the company has opted not to fund capital expenditures in the Canol next year. ConocoPhillips is, after all, a global energy giant, a $62-billion company that operates in 14 countries. It has numerous exploration projects to fund. “Everything competes in that global pool,” Stewart says. Canol didn’t make the cut. The only work that will happen here next year is environmental monitoring and baseline testing.

Around the same time, ConocoPhillips announced it was ramping up activity at its Eagle Ford shale operation in south-central part of Texas. The company, which plans to start full-blown production there this year, drilling 190 wells, believes it’s sitting on as much as 2.5 billion barrels, and hopes to pump 250,000 barrels per day by 2017. A ConocoPhillips rep told the San Antonio Business Journal, possibly with some hyperbole, that Eagle Ford “is probably the greatest energy success story of the 21st Century.” Texas, of course, also boasts ample infrastructure, a deep pool of trained oilpatch workers and an enthusiastic (or compliant, depending on your perspective) regulatory regime. It’s pretty hard for the Canol to compete with that.

Things started out so hopefully. A 2013 NASDAQ analysis estimated the entire Canol could contain as much as 270 billion barrels of oil in place. The same analysis noted, as nearly everyone does, the Sahtu’s high operating costs and lack of infrastructure, but compared the NWT’s tax and royalty regime favourably to those of Alaska, Texas and Alberta. Enthusiastic comparisons to the Bakken shale oil play—which has turned withering rural North Dakota into a region booming so much that local governments can barely keep up with the demand for new housing, civic infrastructure and police—were common.

ConocoPhillips has massive holdings in the Bakken—600,000 acres. It already produces 39,000 barrels per day. It estimates that it’s sitting on as much as 600 million recoverable barrels spread across 800 identified drilling locations. In April, a ConocoPhillips executive told Petroleum News that it plans to “spend about $1 billion a year to grow our production in the Bakken and that will double our production between 2013 and 2017.” It’s pretty hard for the Canol to compete with that, too.

Still, oil guys are quintessential optimists. MGM Energy, also of Calgary, estimates it could be sitting on as much as 11 billion barrels of oil in its Canol holdings. Last year, MGM vice president John Hogg told the Financial Post the Canol could be home to “billions and billions” of barrels of oil. “If it all works the way we think it will, we think this play is as viable as any of the major plays in Canada or North America,” he said. “I would put it up against any one of them and say it’s as good as, if not better than, most of them.” But the Sahtu Land and Water Board ordered an environmental assessment of plans by MGM and then-partner Shell to horizontally frack one well. Shell walked away, and MGM is now on the verge of a takeover, most likely by its former parent company Paramount Resources. Shareholders vote on the matter this month.

ConocoPhillips will spend the better part of the year analyzing drilling results before it knows the true scope of its project’s potential. “Hopefully we’ll get a bit of flow test data to give us an idea,” says Dion McGuinness, ConocoPhillips’ stakeholder engagement co-ordinator, “but it will take quite a long time to analyze and we’ll need more than one season to understand the potential. It’s really a long-term process.”

 And the company still plans to drill 10 more wells in next five years. But April’s news has to come as a letdown for those who would be Canol bulls. In 2012, ConocoPhillips won the right to explore EL-470 by pledging to spend $66.7 million. In the same year, Husky Energy spent $376 million to acquire two parcels near Norman Wells, and also plans to frack. Imperial Oil’s nearby Norman Wells field has pumped 220 million barrels in nearly a century of production. 

Still, could the results so far scare off companies looking to play in the Canol? Not exactly, says Doug Matthews, our oil and gas columnist, and an energy consultant to Northern First Nations and governments. “You need some pretty deep pockets and you need a long timeframe to work shale in the Canol,” he says. “The size of the deposit is ginormous, but it’s going to take time to develop. The good news is that even if it takes 10 years to get to the development phase, it’s going to be there for another 20 after that.”

The ConocoPhillips camp itself lies on the west bank of the Mackenzie, accessible by a company-owned and -operated winter road that crosses the river and then runs about 45 kilometres to the P20 well. Bill Pepper, the field lead (essentially, a foreman) for this project, is shuttling us to the drill pad. Ninety-eight per cent of this winter road is built on pre-existing seismic lines, which means we’re mostly travelling in a straight line through nothing but scrubby jack pines. There isn’t much to look at. “I’m regretting setting the speed limit at 50 here,” Pepper says. The road is patrolled by private security guards, mostly retired Mounties, who are not afraid to write up lead-footed drivers. “I have fired a few people, mostly for speeding on the ice road,” he says.

We first arrive at the camp, roughly halfway to the drill site, which includes five dorms that can each house 38 people. The buildings themselves are modular, designed to be stacked, trucked and forklifted. Boxed lunches are procured. We continue on to the drill pad. The site is surprisingly compact: there are gas stations down south with a bigger footprint.

Rau says the surprisingly small footprint is due to the use of hydraulic fracturing. Conventional vertical drilling involves a single frack stage, directly beneath the wellhead. Because fracking involves multiple stages (the individual blasts of steam, sand and chemicals that force the shale rock open) along the same drill, operators can build multiple wells on a single pad. In P20’s case, there were 10 frack stages; after penetrating 2,000 metres down to the Canol shale, the drill bit does a 90-degree turn and travels horizontally through the source rock for another kilometre. Any oil gets to market via Imperial Oil’s pipeline, while any natural gas is flared off on site.

In a conventional play, the oil is typically trapped in an underground reservoir. Piercing the dome once is enough to access the oil and create the pressure that forces the oil out of the well. In shale (or tight) oil plays, the spaces that contain hydrocarbons are far smaller—tiny pores in the shale. That’s why the rock has to be blasted open repeatedly: there’s no other way to recover the oil economically. “In conventional plays, usually up above there’d be permeable layers the gas and oil would migrate to,” Rau says. “Well, now we’re targeting the source rock.”

ConocoPhillips was eager to show off its operation, keenly aware of the interest and novelty in EL-470, as the first instance of horizontal fracking in the NWT. Fracking is a lightning-rod practice, one that brings attention to what would otherwise be another ho-hum frontier oil exploration project. While almost nobody has called for a halt to exploration in the region, a coalition of environmental and social justice groups called in April for Husky’s nearby project—one that also involves fracking—to undergo an environmental assessment before getting the green light from the Sahtu Land and Water Board. 

But they’ve stopped far short of even demanding a moratorium on fracking, as has happened elsewhere. “In Canada alone, the controversial technique of hydraulic fracturing has been placed under moratorium in Québec [and] Newfoundland [and Labrador] in order to allow time to study the environmental and social impacts of the process before approval is given to use it,” said Lois Little, of the NWT chapter of the Council of Canadians in a news release. “We want to ensure that this new oil extraction process has been carefully studied before further fracking is approved in the NWT.” 

ConocoPhillips, meanwhile, goes to great lengths to stress that the fracking at P20 occurs some 1,600 metres below the water table. It fully discloses all the myriad chemicals used in its fracking process. Pepper says the company’s baseline water test results are shared both with competitors like Husky and regulators like the Sahtu Land and Water Board.

Then there’s the typical allegation levelled at big oil companies: that they’re here only for shareholder profit. It’s hard to argue that isn’t true: that’s what a joint stock corporation is for. But as McGuinness points out, that profit is hardly assured. “We’ve had community members say ‘You’re just taking and taking and taking,’” she says. “But until we get to that production phase, everything’s an expense.”

The next day, I’m at the airport in Norman Wells, waiting for my flight back to Yellowknife. Norman Wells, for its hub status, is still a mighty small town. In the span of 20 minutes I encounter a former newspaper colleague who cannot wait to move back to Yellowknife, and the town’s mayor, Gregor McGregor. Town hall has just initiated the development of a new strategic plan for Norman Wells after a visit to Williston, North Dakota—in the heart of the Bakken play—which saw its population double in about two years. “They had no idea what hit them,” he told me during an earlier visit. 

McGregor is unabashedly pro-development, but Norman Wells is a town of 750 people, where the opening of a single camp can mean instantly-empty store shelves. He doesn’t want to see his town swamped by demand for water, infrastructure and industrial space. 

The ConocoPhillips gang is heading back to Calgary. We make small talk at the check-in counter. They’ve been gracious hosts, and eager to explain the workings of a frack job. But it’s also clear that among all the factors to manage, groundwater impacts, local labour force participation, the regulatory regime, what have you, one is public relations. This has been a charm offensive. McGuinness suggests she could write my story for me. She’s half-joking. Ha ha ha. 

Up Here Business, June 2014.

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